Power Management at a Wellsite

This application is a continuation of U.S. patent application Ser. No. 17/218,762, titled “POWER MANAGEMENT AT A WELLSITE,” filed Mar. 31, 2021, which claims priority to and the benefit of U.S. Provisional Application No. 63/002,574, titled “POWER MANAGEMENT AT A WELLSITE,” filed Mar. 31, 2020, the entire disclosures of which are hereby incorporated herein by reference.

Wells extend into the ground or ocean bed to facilitate recovery of natural deposits of oil, gas, and other materials that are trapped in subterranean rock formations. Well construction (e.g., drilling) operations may be performed at a wellsite by a well construction system (e.g., a drilling rig) having various surface and subterranean well construction equipment operating in a coordinated manner. For example, a drive mechanism, such as a top drive located at a wellsite surface, can be utilized to rotate and advance a drill string into a subterranean rock formation to drill a wellbore. The drill string may include a plurality of drill pipes coupled together and terminating with a drill bit. Length of the drill string may be increased by adding additional drill pipes while depth of the wellbore increases. Drilling fluid may be pumped from the wellsite surface down through the drill string to the drill bit. The drilling fluid lubricates and cools the drill bit and carries drill cuttings from the wellbore back to the wellsite surface. The drilling fluid returning to the surface may then be cleaned and again pumped through the drill string. The well construction equipment of the well construction system may be grouped into various subsystems, wherein each subsystem performs a different operation.

Combustion engine electrical generator units are typically utilized to output electrical power for operating the various well construction equipment. Efficiency of the generator units increases as load on the engine increases. For example, fuel efficiency of the generator units (e.g., diesel fuel generating units) may be optimal at engine loads ranging between, for example, about 50% and about 100%. Efficiency of the generator units is also relatively low during generator warm up periods, which may take several minutes.

Electrical power demand changes frequently and significantly (i.e., to a high degree) during different stages of the well construction operations. During such well construction operations, the generator units collectively output electrical power to match electrical power demand of the well construction equipment, regardless of efficiency. Thus, during stages of well construction operations requiring relatively low levels of electrical power, the generator units collectively operate at low efficiencies. Also, while operating at low efficiency rates, the generator units discharge gas and particulate emissions at relatively high rates. During stages of well construction operations requiring relatively high levels of electrical power, one or more additional generator units may be turned on to provide additional electrical power without permitting the additional generator units to properly warm up, resulting in the generator units operating at low efficiency rates and discharging gas and particulate emissions at relatively high rates.

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify indispensable features of the claimed subject matter, nor is it intended for use as an aid in limiting the scope of the claimed subject matter.

The present disclosure introduces a well construction system that includes well construction equipment, a power supply system, and a control system. The well construction equipment performs well construction operations. The power supply system outputs electrical power to the well construction equipment. The power supply system includes an electrical generator unit, as well as a control system including a processor and a memory storing a computer program code. The computer program code, when executed by the processor, causes the control system to control an electrical power output level of the power supply system during the well construction operations. The computer program code, when executed by the processor, also causes the control system to control operation of the well construction equipment during the well construction operations based on the electrical power output level during the well construction operations and an electrical power demand level of the well construction equipment during the well construction operations.

The present disclosure also introduces a well construction system that includes well construction equipment that performs well construction operations, a power supply system that outputs electrical power to the well construction equipment, and a control system. The power supply system includes an electrical generator unit, as well as a control system having a processor and a memory storing a computer program code and a well construction plan. The well construction plan is indicative of planned tasks to be performed by the well construction equipment as part of the well construction operations to construct a planned well. The computer program code, when executed by the processor, causes the control system to control an electrical power output level of the power supply system based on the well construction plan.

The present disclosure also introduces an apparatus that includes a control system and an electrical energy storage unit. The control system is installable in association with a well construction rig. The well construction rig includes well construction equipment that performs well construction operations to construct a planned well at a wellsite. The well construction rig also includes electrical generator units that output electrical power to the well construction equipment. The control system is communicatively connectable with the electrical generator units via a communication network of the well construction rig. The control system includes a processing device and a memory storing a computer program code. The electrical energy storage unit is installable in association with the well construction rig, electrically connectable with the electrical generator units, and communicatively connectable with the control system via the communication network. The computer program code, when executed by the processor, causes the control system to control the electrical generator units. The computer program code, when executed by the processor, also causes the control system to control the electrical energy storage unit to cause the electrical energy storage unit to alternatingly store electrical power output by the electrical generator units and output the stored electrical power to the well construction equipment during the well construction operations.

The present disclosure also introduces an apparatus including a control system and a hydrogen gas source. The control system is installable in association with a well construction rig that includes well construction equipment that performs well construction operations to construct a planned well at a wellsite. The well construction rig also includes electrical generator units that output electrical power to the well construction equipment. The control system is communicatively connectable with the electrical generator units via a communication network of the well construction rig. The control system includes a processing device and a memory storing a computer program code. The hydrogen gas source is installable in association with the well construction rig, fluidly connectable with each engine of the electrical generator units, and communicatively connectable with the control system via the communication network. The hydrogen gas source can output hydrogen gas into each engine. The computer program code, when executed by the processor, causes the control system to control the electrical generator units and control the hydrogen gas source to cause the hydrogen gas source to output the hydrogen gas into one or more of the engines.

These and additional aspects of the present disclosure are set forth in the description that follows, and/or may be learned by a person having ordinary skill in the art by reading the material herein and/or practicing the principles described herein. At least some aspects of the present disclosure may be achieved via means recited in the attached claims.

It is to be understood that the following disclosure describes many example implementations for different aspects introduced herein. Specific examples of components and arrangements are described below to simplify the present disclosure. These are merely examples, and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for simplicity and clarity, and does not in itself dictate a relationship between the various implementations described herein. Moreover, the formation of a first feature over or on a second feature in the description that follows may include implementations in which the first and second features are formed in direct contact, and may also include implementations in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.

Systems and methods (e.g., processes, operations) according to one or more aspects of the present disclosure may be utilized or otherwise implemented in association with an automated well construction system (i.e., well construction rig) at an oil and gas wellsite, such as for constructing a well (including drilling a wellbore) for extracting hydrocarbons (e.g., oil and/or gas) from a subterranean formation. However, one or more aspects of the present disclosure may be utilized or otherwise implemented in association with other automated systems in the oil and gas industry and other industries. For example, one or more aspects of the present disclosure may be implemented in association with wellsite systems for performing fracturing, cementing, acidizing, chemical injecting, and/or water jet cutting operations, among other examples. One or more aspects of the present disclosure may also be implemented in association with mining sites, building construction sites, and/or other work sites where automated machines or equipment are utilized.

is a schematic view of at least a portion of an example implementation of a well construction systemaccording to one or more aspects of the present disclosure. The well construction systemrepresents an example environment in which one or more aspects of the present disclosure described below may be implemented. The well construction systemmay be or comprise a well construction (e.g., drilling) rig and associated well construction equipment. Although the well construction systemis depicted as an onshore implementation, the aspects described below are also applicable or readily adaptable to offshore implementations.

The well construction systemis depicted in relation to a wellboreformed by rotary and/or directional drilling from a wellsite surfaceand extending into a subterranean formation. The well construction systemcomprises or is associated with various well construction equipment (i.e., wellsite equipment), including surface equipmentlocated at the wellsite surfaceand a drill stringsuspended within the wellbore. The surface equipmentmay include a mast, a derrick, and/or another support structuredisposed over a rig floor. The drill stringmay be suspended within the wellborefrom the support structure. The support structureand the rig floorare collectively supported over the wellboreby legs and/or other support structures (not shown).

The drill stringmay comprise a bottom-hole assembly (BHA)and meansfor conveying the BHAwithin the wellbore. The conveyance meansmay comprise a plurality of interconnected tubulars, such as drill pipe, heavy-weight drill pipe (HWDP), wired drill pipe (WDP), tough logging condition (TLC) pipe, and drill collars, among other examples. The conveyance meansmay instead comprise coiled tubing for conveying the BHAwithin the wellbore. A downhole end of the BHAmay include or be coupled to a drill bit. Rotation of the drill bitand the weight of the drill stringcollectively operate to form the wellbore. The drill bitmay be rotated from the wellsite surfaceand/or via a downhole mud motorconnected with the drill bit. The BHAmay also include various downhole devices and/or tools,.

The support structuremay support a driver, such as a top drive, operable to connect (perhaps indirectly) with an upper end of the drill string, and to impart rotary motionand vertical motionto the drill string, including the drill bit. However, another driver, such as a kelly and rotary table (neither shown), may be utilized instead of or in addition to the top driveto impart the rotary motionto the drill string. The top driveand the connected drill stringmay be suspended from the support structurevia a hoisting system or equipment, which may include a traveling block, a crown block, and a drawworksstoring a support cable or line. The crown blockmay be connected to or otherwise supported by the support structure, and the traveling blockmay be coupled with the top drive. The drawworksmay be mounted on or otherwise supported by the rig floor. The crown blockand traveling blockcomprise pulleys or sheaves around which the support lineis reeved to operatively connect the crown block, the traveling block, and the drawworks(and perhaps an anchor). The drawworksmay thus selectively impart tension to the support lineto lift and lower the top drive, resulting in the vertical motion. The drawworksmay comprise a drum, a base, and a prime mover (e.g., an electric motor) (not shown) operable to drive the drum to rotate and reel in the support line, causing the traveling blockand the top driveto move upward. The drawworksmay be operable to reel out the support linevia a controlled rotation of the drum, causing the traveling blockand the top driveto move downward.

The top drivemay comprise a grabber, a swivel (neither shown), elevator linksterminating with an elevator, and a drive shaftoperatively connected with a prime mover (e.g., an electric motor) (not shown), such as via a gear box or transmission (not shown). The drive shaftmay be selectively coupled with the upper end of the drill stringand the prime mover may be selectively operated to rotate the drive shaftand the drill stringcoupled with the drive shaft. Thus, during drilling operations, the top drive, in conjunction with operation of the drawworks, may advance the drill stringinto the formationto form the wellbore. The elevator linksand the elevatorof the top drivemay handle tubulars (e.g., drill pipes, drill collars, casing joints, etc.) that are not mechanically coupled to the drive shaft. For example, when the drill stringis being tripped into or out of the wellbore, the elevatormay grasp the tubulars of the drill stringsuch that the tubulars may be raised and/or lowered via the hoisting equipment mechanically coupled to the top drive. The grabber may include a clamp that clamps onto a tubular when making up and/or breaking out a connection of a tubular with the drive shaft. The top drivemay have a guide system (not shown), such as rollers that track up and down a guide rail on the support structure. The guide system may aid in keeping the top drivealigned with the wellbore, and in preventing the top drivefrom rotating during drilling by transferring reactive torque to the support structure.

The drill stringmay be conveyed within the wellborethrough various fluid control devices disposed at the wellsite surfaceon top of the wellboreand perhaps below the rig floor. The fluid control devices may be operable to control fluid within the wellbore. The fluid control devices may include a blowout preventer (BOP) stackfor maintaining well pressure control and comprising a series of pressure barriers (e.g., rams) between the wellboreand an annular preventer. The fluid control devices may also include a rotating control device (RCD)mounted above the annular preventer. The fluid control devices,,may be mounted on top of a wellhead. A power unit(i.e., a BOP control or closing unit) may be operatively connected with one or more of the fluid control devices,,and operable to actuate, drive, operate, or otherwise control one or more of the fluid control devices,,. The power unitmay be or comprise a hydraulic fluid power unit fluidly connected with the fluid control devices,,and selectively operable to hydraulically drive various portions (e.g., rams, valves, seals) of the fluid control devices,,. The power unitmay comprise one or more hydraulic pumps actuated by electric motors and operable to pressurize hydraulic fluid for operating the fluid control devices,,as described herein.

The well construction systemmay further include a drilling fluid circulation system or equipment operable to circulate fluids between the surface equipmentand the drill bitduring drilling and other operations. For example, the drilling fluid circulation system may be operable to inject a drilling fluid from the wellsite surfaceinto the wellborevia an internal fluid passageextending longitudinally through the drill string. The drilling fluid circulation system may comprise a pit, a tank, and/or other fluid containerholding the drilling fluid(i.e., drilling mud), and one or more mud pump units(i.e., drilling fluid pumps) operable to move the drilling fluidfrom the containerinto the fluid passageof the drill stringvia a fluid conduitextending from the pump unitsto the top driveand an internal passage extending through the top drive. Each pump unitmay comprise a fluid pump (not shown) operable to pump the drilling fluidand a prime mover (e.g., an electric motor) (not shown) operable to drive the corresponding fluid pump. The fluid conduitmay comprise one or more of a pump discharge line, a stand pipe, a rotary hose, and a gooseneck connected with a fluid inlet of the top drive. The pumpsand the containermay be fluidly connected by a fluid conduit, such as a suction line.

During drilling operations, the drilling fluid may continue to flow downhole through the internal passageof the drill string, as indicated by directional arrow. The drilling fluid may exit the BHAvia portsin the drill bitand then circulate uphole through an annular space(“annulus”) of the wellboredefined between an exterior of the drill stringand the wall of the wellbore, such flow being indicated by directional arrows. In this manner, the drilling fluid lubricates the drill bitand carries formation cuttings uphole to the wellsite surface. The returning drilling fluid may exit the annulusvia different fluid control devices during different stages or scenarios of well drilling operations. For example, the drilling fluid may exit the annulusvia a bell nipple, the RCD, or a ported adapter(e.g., a spool, cross adapter, a wing valve, etc.) located below one or more rams of the BOP stack.

During normal drilling operations, the drilling fluid may exit the annulusvia the bell nippleand then be directed toward drilling fluid reconditioning equipmentvia a fluid conduit(e.g., gravity return line) to be cleaned and/or reconditioned, as described below, before being returned to the containerfor recirculation. During managed pressure drilling operations, the drilling fluid may exit the annulusvia the RCDand then be directed into a choke manifold(e.g., a managed pressure drilling choke manifold) via a fluid conduit(e.g., a drilling pressure control line). The choke manifoldmay include at least one choke and a plurality of fluid valves (neither shown) collectively operable to control the flow through and out of the choke manifold. Backpressure may be applied to the annulusby variably restricting flow of the drilling fluid or other fluids flowing through the choke manifold. The greater the restriction to flow through the choke manifold, the greater the backpressure applied to the annulus. The drilling fluid exiting the choke manifoldmay then pass through the drilling fluid reconditioning equipmentbefore being returned to the containerfor recirculation. During well pressure control operations, such as when one or more rams of the BOP stackis closed, the drilling fluid may exit the annulusvia the ported adapterand be directed into a choke manifold(e.g., a rig choke manifold, well control choke manifold) via a fluid conduit(e.g., rig choke line). The choke manifoldmay include at least one choke and a plurality of fluid valves (neither shown) collectively operable to control the flow of the drilling fluid through the choke manifold. Backpressure may be applied to the annulusby variably restricting flow of the drilling fluid (and other fluids) flowing through the choke manifold. The drilling fluid exiting the choke manifoldmay then pass through the drilling fluid reconditioning equipmentbefore being returned to the containerfor recirculation.

Before being returned to the container, the drilling fluid returning to the wellsite surfacemay be cleaned and/or reconditioned via the drilling fluid reconditioning equipment, which may include one or more of liquid-gas (i.e., mud gas) separators, shale shakers, and other drilling fluid cleaning and reconditioning equipment. The liquid-gas separatorsmay remove formation gases entrained in the drilling fluid discharged from the wellboreand the shale shakersmay separate and remove solid particles(e.g., drill cuttings) from the drilling fluid. The drilling fluid reconditioning equipmentmay further comprise other equipmentoperable to remove additional gas and finer formation cuttings from the drilling fluid and/or modify chemical and/or physical properties or characteristics (e.g., rheology, density, etc.) of the drilling fluid. For example, the drilling fluid reconditioning equipmentmay include a degasser, a desander, a desilter, a centrifuge, a mud cleaner, and/or a decanter, among other examples. The drilling fluid reconditioning equipmentmay further include chemical containers and mixing equipment collectively operable to mix or otherwise add selected chemicals to the drilling fluid returning from the wellboreto modify chemical and/or physical properties or characteristics of the drilling fluid being pumped back into the wellbore. Intermediate tanks/containers (not shown) may be utilized to hold the drilling fluid while the drilling fluid progresses through the various stages or portions,,of the drilling fluid reconditioning equipment. The cleaned and reconditioned drilling fluid may be transferred to the fluid container, the solid particlesremoved from the drilling fluid may be transferred to a solids container(e.g., a reserve pit), and/or the removed gas may be transferred to a flare stackvia a conduit(e.g., a flare line) to be burned or to a container (not shown) for storage and removal from the wellsite.

The surface equipmentmay include a tubular handling system or equipment operable to store, move, connect, and disconnect tubulars (e.g., drill pipes) to assemble and disassemble the conveyance meansof the drill stringduring drilling operations. For example, a catwalkmay be utilized to convey tubulars from a ground level, such as along the wellsite surface, to the rig floor, permitting the elevatorto grab and lift the tubulars above the wellborefor connection with previously deployed tubulars. The catwalkmay have a horizontal portion and an inclined portion that extends between the horizontal portion and the rig floor. The catwalkmay comprise a skatemovable along a groove (not shown) extending longitudinally along the horizontal and inclined portions of the catwalk. The skatemay be operable to convey (e.g., push) the tubulars along the catwalkto the rig floor. The skatemay be driven along the groove by a drive system (not shown), such as a pulley system or a hydraulic system. Additionally, one or more racks (not shown) may adjoin the horizontal portion of the catwalk. The racks may have a spinner unit for transferring tubulars to the groove of the catwalk. The tubular handling system may comprise a plurality of actuators collectively operable to move various portions of the tubular handling equipment to perform the methods and operations described herein. The actuators may be or comprise electric motors and/or hydraulic cylinders and rotary actuators. The hydraulic cylinders and rotary actuators may be powered by hydraulic power packs comprising hydraulic pumps actuated by electric motors to pressurize hydraulic fluid.

An iron roughneckmay be positioned on the rig floor. The iron roughneckmay comprise a torqueing portion, such as may include a spinner and a torque wrench comprising a lower tong and an upper tong. The torqueing portionof the iron roughneckmay be moveable toward and at least partially around the drill string, such as may permit the iron roughneckto make up and break out connections of the drill string. The torqueing portionmay also be moveable away from the drill string, such as may permit the iron roughneckto move clear of the drill stringduring drilling operations. The spinner of the iron roughneckmay be utilized to apply low torque to make up and break out threaded connections between tubulars of the drill string, and the torque wrench may be utilized to apply a higher torque to tighten and loosen the threaded connections. The iron roughneck may comprise a plurality of actuators collectively operable to move various portions of the iron roughneck to perform the methods and operations described herein. The actuators may be or comprise electric motors.

A set of slipsmay be located on the rig floor, such as may accommodate therethrough the drill stringduring tubular make up and break out operations and during the drilling operations. The slipsmay be in an open position during drilling operations to permit advancement of the drill string, and in a closed position to clamp the upper end (e.g., the uppermost tubular) of the drill stringto thereby suspend and prevent advancement of the drill stringwithin the wellbore, such as during the make up and break out operations.

During drilling operations, the various well construction equipment of the well construction systemmay progress through a plurality of coordinated operations (i.e., operational sequences) to drill or otherwise construct the wellbore. The operational sequences may change based on a well construction plan, status of the well, status of the subterranean formation, stage of drilling operations (e.g., tripping, drilling, tubular handling, etc.), and type downhole tubulars (e.g., drill pipe) utilized, among other examples.

During drilling operations, the hoisting system lowers the drill stringwhile the top driverotates the drill stringto advance the drill stringdownward within the wellboreand into the formation. During the advancement of the drill string, the slipsare in an open position, and the iron roughneckis moved away or is otherwise clear of the drill string. When the upper end of the drill string(i.e., the upper end of the uppermost tubular of the drill string) connected to the drive shaftis near the slipsand/or the rig floor, the top driveceases rotating and the slipsclose to clamp the upper end of the drill string. The grabber of the top drivethen clamps the uppermost tubular connected to the drive shaft, and the drive shaftrotates in a direction reverse from the drilling rotation to break out the connection between the drive shaftand the uppermost tubular. The grabber of the top drivemay then release the uppermost tubular.

Multiple tubulars may be loaded on the rack of the catwalkand individual tubulars may be transferred from the rack to the groove in the catwalk, such as by the spinner unit. The tubular positioned in the groove may be conveyed along the groove by the skateuntil the box end of the tubular projects above the rig floor. The elevatorof the top drivethen grasps the protruding box end, and the drawworksmay be operated to lift the top drive, the elevator, and the new tubular.

The hoisting system then raises the top drive, the elevator, and the new tubular until the tubular is aligned with the upper portion of the drill stringclamped by the slips. The iron roughneckis moved toward the drill string, and the lower tong of the torqueing portionclamps onto the upper end of the drill string. The spinning system threadedly connects the lower end (i.e., pin end) of the new tubular with the upper end (i.e., box end) of the drill string. The upper tong then clamps onto the new tubular and rotates with high torque to complete making up the connection with the drill string. In this manner, the new tubular becomes part of the drill string. The iron roughneckthen releases and moves clear of the drill string.

The grabber of the top drivemay then clamp onto the drill string. The drive shaftis brought into contact with the upper end of the drill string(e.g., the box end of the uppermost tubular) and rotated to make up a connection between the drill stringand the drive shaft. The grabber then releases the drill string, and the slipsare moved to the open position. The drilling operations may then resume.

The tubular handling equipment may further include a tubular handling manipulator (THM)disposed in association with a vertical pipe rackfor storing tubulars(e.g., drill pipes, drill collars, drill pipe stands, casing joints, etc.). The vertical pipe rackmay comprise or support a fingerboarddefining a plurality of slots configured to support or otherwise hold the tubularswithin or above a setback(e.g., a platform or another area) located adjacent to, along, or below the rig floor. The fingerboardmay comprise a plurality of fingers (not shown), each associated with a corresponding slot and operable to close around and/or otherwise interpose individual tubularsto maintain the tubularswithin corresponding slots of the fingerboard. The vertical pipe rackmay be connected with and supported by the support structureor another portion of the wellsite system. The fingerboard/setbackprovide storage (e.g., temporary storage) of tubularsduring various operations, such as during and between tripping out and tripping of the drill string. The THMmay comprise a plurality of actuators collectively operable to move various portions of the THMto perform the methods and operations described herein. The actuators may be or comprise electric motors.

The THMmay be operable to transfer the tubularsbetween the fingerboard/setbackand the drill string(i.e., space above the suspended drill string). For example, the THMmay include armsterminating with clamps, such as may be operable to grasp and/or clamp onto one of the tubulars. The armsof the THMmay extend and retract, and/or at least a portion of the THMmay be rotatable and/or movable toward and away from the drill string, such as may permit the THMto transfer the tubularbetween the fingerboard/setbackand the drill string.

To trip out the drill string, the top driveis raised, the slipsare closed around the drill string, and the elevatoris closed around the drill string. The grabber of the top driveclamps the upper end of a tubular of the drill stringcoupled to the drive shaft. The drive shaftthen rotates in a direction reverse from the drilling rotation to break out the connection between the drive shaftand the drill string. The grabber of the top drivethen releases the tubular of the drill string, and the drill stringis suspended by (at least in part) the elevator. The iron roughneckis moved toward the drill string. The lower tong clamps onto a lower tubular below a connection of the drill string, and the upper tong clamps onto an upper tubular above that connection. The upper tong then rotates the upper tubular to provide a high torque to break out the connection between the upper and lower tubulars. The spinning system then rotates the upper tubular to separate the upper and lower tubulars, such that the upper tubular is suspended above the rig floorby the elevator. The iron roughneckthen releases the drill stringand moves clear of the drill string.

The THMmay then move toward the drill stringto grasp the tubular suspended from the elevator. The elevatorthen opens to release the tubular. The THMthen moves away from the drill stringwhile grasping the tubular with the clamps, places the tubular in the fingerboard/setback, and releases the tubular for storage. This process is repeated until the intended length of drill stringis removed from the wellbore.

The surface equipmentof the well construction systemmay also comprise a control centerfrom which various portions of the well construction system, such as the top drive, the hoisting system, the tubular handling system, the drilling fluid circulation system, the well control system, and the BHA, among other examples, may be monitored and controlled. The control centermay be located on the rig flooror another location of the well construction system. The control centermay comprise a facility(e.g., a room, a cabin, a trailer, etc.) containing a control workstation, which may be operated by rig personnel(e.g., a driller or other human rig operator) to monitor and control various well construction equipment or portions of the well construction system. The control workstationmay comprise or be communicatively connected with a central controller(e.g., a processing device, a computer, etc.), such as may be operable to receive, process, and output information to monitor operations of and provide control to one or more portions of the well construction system. For example, the central controllermay be communicatively connected with the various surface and downhole equipment described herein, and may be operable to receive signals from and transmit signals to such equipment to perform various operations described herein. The central controllermay store executable computer program code, instructions, and/or operational parameters or set-points, including for implementing one or more aspects of methods and operations described herein. The central controllermay be located within and/or outside of the facility. Although it is possible that the entirety of the central controlleris implemented within one device, it is also contemplated that one or more components or functions of the central controllermay be implemented across multiple devices, some or an entirety of which may be implemented as part of the control centerand/or located within the facility.

The control workstationmay be operable for entering or otherwise communicating control data (e.g., commands, signals, information, etc.) to the central controllerand other equipment controller by the rig personnel, and for displaying or otherwise communicating information from the central controllerto the rig personnel. The control workstationmay comprise a plurality of human-machine interface (HMI) devices, including one or more input devices(e.g., a keyboard, a mouse, a joystick, a touchscreen, etc.) and one or more output devices(e.g., a video monitor, a touchscreen, a printer, audio speakers, etc.). Communication between the central controller, the input and output devices,, and the various well construction equipment may be via wired and/or wireless communication means. However, for clarity and ease of understanding, such communication means are not depicted, and a person having ordinary skill in the art will appreciate that such communication means are within the scope of the present disclosure.

Well construction systems within the scope of the present disclosure may include more or fewer components than as described above and depicted in. Additionally, various equipment and/or subsystems of the well construction systemshown inmay include more or fewer components than as described above and depicted in. For example, various engines, electric motors, hydraulics, actuators, valves, and/or other components not explicitly described herein may be included in the well construction system, and are within the scope of the present disclosure.

The present disclosure further provides various implementations of systems and/or methods for controlling one or more portions of the well construction system.is a schematic view of at least a portion of an example implementation of a drilling rig control system(hereinafter “rig control system”) for monitoring and controlling various well construction equipment of the well construction systemshown in. The rig control systemmay comprise one or more features of the well construction system, including where indicated by the same reference numerals. Accordingly, the following description refers to, collectively.

The various pieces of well construction equipment described above and shown inmay each comprise one or more actuators (e.g., combustion, hydraulic, and/or electrical) that, when operated, may cause the corresponding well construction equipment to perform intended actions (e.g., work, tasks, movements, operations, etc.). Each piece of well construction equipment may further carry or comprise one or more sensors disposed in association with a corresponding actuator or another portion of the piece of equipment. Each sensor may be communicatively connected with a corresponding equipment controller and operable to generate sensor data (e.g., electrical sensor signals or measurements, feedback signals, feedback loop, etc.) indicative of an operational (e.g., mechanical, physical, etc.) status of the corresponding piece of well construction equipment or actuator of that piece of equipment, thereby permitting the operational status of the piece of equipment to be monitored by the equipment controller. The sensor data may be utilized by the equipment controller as feedback data, permitting operational control of the piece of well construction equipment and coordination with other well construction equipment.

The rig control systemmay be in real-time communication with and utilized to monitor and/or control various portions, components, and equipment of the well construction systemdescribed herein. The equipment of the well construction systemmay be grouped into several subsystems, each operable to perform a corresponding operation and/or a portion of the well construction operations described herein. The subsystems may include a tubular handling (TH) system, a fluid processing (FP) system, a managed pressure drilling (MPD) system, a drilling fluid circulation (DFC) system, a drill string rotation system (DSR) system, a choke pressure control (CPC) system, a well pressure control (WC) system, and a power supply (PS) system.

The TH systemmay include the support structure, a tubular hoisting system (e.g., the drawworks, the elevator links, the elevator, and the slips), a tubular handling system or equipment (e.g., the catwalk, the THM, the setback, and the iron roughneck), and/or other tubular handling equipment. Accordingly, the TH systemmay perform tubular handling and hoisting operations. The TH systemmay also serve as a support platform for tubular rotation equipment and a staging ground for rig operations, such as connection make up and break out operations described above. The FP systemmay include the drilling fluid reconditioning equipment, the flare stack, the containers,, and/or other equipment. Accordingly, the FP systemmay perform fluid cleaning, reconditioning, and mixing operations. The MPD systemmay include the RCD, the power unit, the choke manifold, and/or other equipment. The DFC systemmay comprise the pumps, the drilling fluid container, the bell nipple, and/or other equipment collectively operable to pump and circulate the drilling fluid at the wellsite surface and downhole. The DSR systemmay include the top driveand/or the rotary table and kelly. The CPC systemmay comprise the choke manifold, the ported adapter, and/or other equipment, and the WC systemmay comprise the BOP stack, the power unit, and a BOP control station for controlling the power unit. The PS systemmay comprise various sources of electrical power operable to power the well construction equipment of the well construction system, including the well construction equipment of the well construction subsystems-. The PS systemmay also include various means for transferring and/or distributing electrical power and fuel to the well construction equipment and between various pieces of equipment of the PS system, including electrical power conductors, electrical connectors, electrical relays, fluid conductors, fluid connectors, and fluid valves, among other examples. The sources of electrical power may include electric generators, electrical energy storage devices (e.g., batteries, capacitors, etc.), fuel storage devices, and a remote electrical power grid, among other examples. Each of the well construction subsystems-may further comprise various communication equipment (e.g., modems, network interface cards, etc.) and communication conductors (e.g., cables), communicatively connecting the equipment (e.g., sensors and actuators) of each subsystem-with a central controllerand a control workstation. Although the well construction equipment listed above and shown inis associated with certain wellsite subsystems-, such associations are merely examples that are not intended to limit or prevent such well construction equipment from being associated with two or more wellsite subsystems-and/or different wellsite subsystems-.

The rig control systemmay include various local controllers-, each operable to control various well construction equipment of a corresponding subsystem-and/or an individual piece of well construction equipment of a corresponding subsystem-. As described above, each well construction subsystem-includes various well construction equipment comprising corresponding actuators-for performing operations of the well construction system. Each subsystem-may include various sensors-operable to generate sensor data (e.g., signals, information, measurements, etc.) indicative of operational status of the well construction equipment of each subsystem-. Each local controller-may output control data (e.g., commands, signals, information, etc.) to one or more actuators-to perform corresponding actions of a piece of equipment or subsystem-. Each local controller-may receive sensor data generated by one or more sensors-indicative of operational status of an actuator or another portion of a piece of equipment or subsystem-. Although the local controllers-, the sensors-, and the actuators-are each shown as a single block, it is to be understood that each local controller-, sensor-, and actuator-may be or comprise a plurality of local controllers, sensors, and actuators.

The sensors-may include sensors utilized for operation of the various subsystems-of the well construction system. For example, the sensors-may include cameras, position sensors, speed sensors, acceleration sensors, pressure sensors, force sensors, temperature sensors, flow rate sensors, vibration sensors, electrical current sensors, electrical voltage sensors, resistance sensors, gesture detection sensors or devices, voice actuated or recognition devices or sensors, chemical sensors, exhaust sensors, and/or other examples. The sensor data may include signals, information, and/or measurements indicative of equipment operational status (e.g., on or off, percent load, up or down, set or released, etc.), drilling parameters (e.g., depth, hook load, torque, etc.), auxiliary parameters (e.g., vibration data of a pump), flow rate, temperature, operational speed, position, and pressure, among other examples. The acquired sensor data may include or be associated with a timestamp (e.g., date and/or time) indicative of when the sensor data was acquired. The sensor data may also or instead be aligned with a depth or other drilling parameter.

The local controllers-, the sensors-, and the actuators-may be communicatively connected with the central controller. For example, the local controllers-may be in communication with the sensors-and actuators-of the corresponding subsystems-via local communication networks (e.g., field buses) (not shown) and the central controllermay be in communication with the subsystems-via a central communication network(e.g., a data bus, a field bus, a wide-area-network (WAN), a local-area-network (LAN), etc.). The sensor data generated by the sensors-of the subsystems-may be made available for use by the central controllerand/or the local controllers-. Similarly, control data output by the central controllerand/or the local controllers-may be automatically communicated to the various actuators-of the subsystems-, perhaps pursuant to predetermined programming, such as to facilitate well construction operations and/or other operations described herein. Although the central controlleris shown as a single device (i.e., a discrete hardware component), it is to be understood that the central controllermay be or comprise a plurality of equipment controllers and/or other electronic devices collectively operable to monitor and control operations (i.e., computational processes or methods) of the well construction system. The central controllermay be located within or form a portion of a control center, although a portion of the central controllermay instead be external to the control center.

The sensors-and actuators-may be monitored and/or controlled by corresponding local controllers-and/or the central controller. For example, the central controllermay be operable to receive sensor data from the sensors-of the wellsite subsystems-in real-time, and to output real-time control data directly to the actuators-of the subsystems-based on the received sensor data. However, certain operations of the actuators-of each subsystem-may be controlled by a corresponding local controller-, which may control the actuators-based on sensor data received from the sensors-of the corresponding subsystem-and/or based on control data received from the central controller.

The rig control systemmay be a tiered control system, wherein control of the subsystems-of the well construction systemmay be provided via a first tier of the local controllers-and a second tier of the central controller. The central controllermay facilitate control of one or more of the subsystems-at the level of each individual subsystem-. For example, in the FP system, sensor data may be fed into the local controller, which may respond to control the actuators. However, for control operations that involve multiple subsystems-, the control may be coordinated through the central controlleroperable to coordinate control of well construction equipment of two, three, four, or more (or each) of the subsystems-. For example, coordinated control operations may include the control of downhole pressure during tripping. The downhole pressure may be affected by the DFC system(e.g., pump rate), the MPD system(e.g., position of the choke), and the TH system(e.g., tripping speed). Thus, when it is intended to maintain certain downhole pressure during tripping, the central controllermay output control data to two or more of the participating subsystems-.

As described above, the central controllermay control various operations of the subsystems-via analysis of sensor data from one or more of the wellsite subsystems-to facilitate coordinated control between the subsystems-. The central controllermay generate control data to coordinate operations of various well construction equipment of the subsystems-. The control data may include, for example, commands from rig personnel, such as turn on or turn off a pump, switch on or off a fluid valve, and update a physical property set-point, among other examples. The local controllers-may each include a fast control loop that directly obtains sensor data and executes, for example, a control algorithm to generate the control data. The central controllermay include a slow control loop to periodically obtain sensor data and generate the control data.

The rig control system, including the central controllerand the local controllers-, facilitates operation of the well construction equipment in an equipment focused manner, such as to maintain the choke pressure to a certain value or to rotate the drill string at a certain rotational speed. The rig control systemmay also coordinate operations of certain pieces of equipment to achieve intended operations, such as to move a tubular from the fingerboard to the well center, break up a tubular stand from the well center, or rack an individual tubular back to the fingerboard. Each such operation utilizes coordinated control of multiple pieces of pipe handling equipment by the central controller.

The central controller, the local controllers-, and/or other controllers or processing devices (referred to hereinafter as “equipment controllers”) of the rig control systemmay each or collectively be operable to receive and store machine-readable and executable program code instructions (e.g., computer program code, algorithms, programmed processes or operations, etc.) on a memory device (e.g., a memory chip) and then execute the program code instructions to run, operate, or perform a control process for monitoring and/or controlling the well construction equipment of the well construction system.

The central controllermay run (i.e., execute) a control process(e.g., a coordinated control process or another computer process) and each local controller-may run a corresponding control process (e.g., a local control process or another computer process, not shown). Two or more of the local controllers-may run their local control processes to collectively coordinate operations between well construction equipment of two or more of the subsystems-.